Modern drilling operations used to create boreholes in the earth for the production of oil, gas, and geothermal energy typically employ rotary drilling techniques. In rotary drilling, a borehole is created by the rotation of a tubular drill string having a drill bit secured to its lower end. As drilling proceeds, additional tubular segments are periodically added to the drill string to deepen the hole. While drilling, a pressurized fluid is continually injected into the drill string. This fluid passes into the borehole through nozzles in the drill bit and returns to the surface through the annular channel between the drill string and the walls of the borehole. The drilling fluid carries the rock cuttings out of the borehole, cools and lubricates the drill bit, and serves several other functions.
The most common type of bit used in rotary drilling is known as a rotary-cone bit. Rotary-cone bits have a number of spindles at their lower end with each spindle serving as an axle for a cutting element, commonly referred to as a cone. The spindles and cones are configured so that a cutting face of each cone rests on the bottom of the borehole. As the bit is rotated, the cones rotate on the spindles. The exposed surface of each cone is provided with steel teeth or carbide inserts which penetrate into the bottom of the borehole as the drill string turns.
Drill bits undergo wear in the course of drilling operations. One type of wear is the dulling of the cutting elements. This causes the penetration rate of the bit to decrease. This is readily observable at the surface, permitting the driller to pull the drill string at the appropriate point to replace the bit.
There are other types of wear, not readily apparent at the surface, which have posed longstanding problems for the industry. One of these types of wear is specific to roller-cone bits. In drilling with a roller-cone bit, the bearing surfaces between each cone and spindle will wear. As these surfaces wear, the cone will generally begin to rotate eccentrically about the spindle. As bearing wear progresses, this eccentric rotation increases until the cone seizes or falls off the spindle. If a bit bearing should fail and leave a cone in the wellbore, it is often necessary to withdraw the drill string and suspend drilling operations until the lost cone can be fished from the well. The resulting delay can be very expensive, Particularly in offshore wells.
It has long been desired to develop an inexpensive and reliable means of indicating when a bit is about to lose a cone. At present, drillers often elect to replace the bit well before they think it likely that a problem has developed to avoid the possibility of needing to fish a cone from the well. Oftentimes, the bits are discovered to have considerable life remaining when they are brought to the surface. If there were some means for determining when bearing wear has reached the point where further drilling poses the risk of losing a cone, each bit could be used for its maximum effective life without risking the downtime that a lost cone entails.
U.S. Pat. No. 4,655,300, issued to Davis et al. on Apr. 7, 1987, discloses a type of monitor which has shown considerable promise as a practical solution to detecting and indicating bit bearing wear. This monitor includes a wear sensor, a ball for blocking a drilling fluid jet, and a tensioned wire which controls a device retaining the ball away from the jet until the sensor detects a predetermined degree of wear. One problem with this monitor is that the operation of drilling passages for the tensioned wire has required considerable attention to ensure that the several passages required for each monitor meet at the desired point in the bit body. Threading the tensioned wire through the sharp intersection created by the drilling operation also poses a problem. It would be desirable to develop an improved monitor design and fabrication method in which these problems are avoided.